Methods of determining cation exchange sites occuped by crude oil and the wettability of cation exchange sites in rock core samples in a non-preserved state

ABSTRACT

A method for determining properties of different cation exchange sites in a rock core sample, at a non-preserved state of the rock core sample may include providing a rock core sample in a non-preserved state; displacing all native components out of the rock core sample; subjecting the rock core sample clean of native components to a plurality of coreflooding steps to determine a total amount of exchangeable cations adsorbed onto the cation exchange sites when the rock core sample is clean of native components; injecting formation brine and then a reservoir crude oil into the rock core sample until reaching irreducible water saturation and equilibrium between formation brine, the reservoir crude oil, and the cation exchange sites, such that rock core sample includes a plurality of indigenous exchangeable cations adsorbed onto the cation exchange sites, a plurality of cation exchange sites occupied by a crude oil, and one or more fluids occupying pore spaces in the rock core sample; subjecting the rock core sample to a plurality of coreflooding steps, the plurality of coreflooding step displacing the plurality of indigenous exchangeable cations, the crude oil, and the one or more fluids in at least two separate coreflooding steps to render the rock core sample clean of the indigenous cations; determining an amount of indigenous exchangeable cations adsorbed onto the cation exchange sites; and determining at least one property of different cation exchange sites in the rock core sample based on the amount of indigenous exchangeable cations and the total amount of exchangeable cations.

BACKGROUND

A common practice in the oil and gas industry is to inject water into ahydrocarbon reservoir to maintain its pressure and displace hydrocarbonsto production wells. This injection of water is commonly referred to assecondary stage injection or secondary recovery. Seawater and aquiferwater are some of the more widely used resources for injection.Injection of a second fluid in order to displace additional hydrocarbonsafter no more hydrocarbons are being extracted using the first fluid isreferred to as tertiary stage injection or tertiary recovery. Aremaining portion of the initial hydrocarbons in the reservoir can beextracted utilizing expensive enhanced recovery techniques, such ascarbon dioxide (CO₂) injection or chemical flooding. A relatively morerecent technique involves injection of aqueous solutions with modifiedionic compositions.

Understanding properties of the hydrocarbon reservoir can assist inoptimizing extraction of the stored hydrocarbons from the reservoir. Onetechnique to understand properties of the hydrocarbon reservoir is todevelop computer-generated software models of all or portions of thereservoir. To develop such models, a reservoir rock sample from thehydrocarbon reservoir is evaluated and results of the evaluation areprovided as an input to the computer software program that generates thesoftware models. The reservoir rock sample can be evaluated byperforming one or more of several experiments under laboratoryconditions or under reservoir conditions (that is, the conditionsexperienced by the sample in the hydrocarbon reservoir). Rockwettability, specifically, the wettability of the porous structurewithin the rock, is one of the parameters of the reservoir rock samplethat can be evaluated.

Wettability is the tendency of a fluid to spread across or adhere to asolid surface in the presence of other immiscible fluids. Wettabilitycan describe the preference of a solid to be in contact with one fluidrather than another. In relation to the oil and gas industry,wettability can refer to the interaction between fluids such ashydrocarbons or water and a reservoir rock. The wettability of areservoir can affect the hydrocarbon extraction process. Becausewettability can influence not only the profile of initial hydrocarbonsaturation but also the hydrocarbon extraction process, such as waterflooding and enhanced oil recovery (EOR) processes. However,conventional wettability measurement methods cannot determine thewettability of different cation exchange sites.

Further, existence of clay in reservoir formations has a great impact onreservoir quality of sandstone facies. Clay minerals have differenteffects on the characteristics of oil reservoirs such as reduction ofeffective porosity and permeability or overestimation of watersaturation due to the increased conductivity. In addition, the presenceof clay causes the instability of some parts of wellbore wall. For thesereasons, the study of clays in petroleum related investigations is sovital. Cation exchange capacity (CEC) is one of the parameters that isuseful for identifying clays and their physical and chemical properties.

The CEC of a rock sample is often determined by a wet chemistry method.However, the determined cation exchange capacity by a wet chemistrymethod is not reservoir representative for the following reasons: (1)the rock sample is cleaned to remove any oil in the rock sample, whichis not representative of the in-situ reservoir conditions; (2) the rocksample is ground to fine particles. However, excessive grinding willincrease the cation exchange capacity by exposing more cation exchangesites than the case at the in-situ reservoir conditions, resulting inthe overestimation cation exchange capacity. On the other hand,insufficient grinding will lead to some reservoir representative cationexchange sites not being exposed, resulting in underestimation of thecation exchange capacity; and (3) the determined cation exchangecapacity does not identity any reservoir representative exchangeablecations on the exchange sites and which of the sites are occupied bycrude oil. Oil adsorbed onto the cation exchange sites may impact thecation exchange capacity. Cation exchange between a rock surface and abrine being flushed therethrough can desorb oil that is adsorbed to thesurface, thereby impacting oil recovery efforts from the reservoir.

Accordingly, there exists a continuing need for developments in rocksample analysis to improve the enhanced oil recovery efforts.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In one aspect, embodiments disclosed herein relate to a method fordetermining properties of different cation exchange sites in a rock coresample, at a non-preserved state of the rock core sample includesproviding a rock core sample in a non-preserved state; displacing allnative components out of the rock core sample; subjecting the rock coresample clean of native components to a plurality of coreflooding stepsto determine a total amount of exchangeable cations adsorbed onto thecation exchange sites when the rock core sample is clean of nativecomponents; injecting formation brine and then a reservoir crude oilinto the rock core sample until reaching irreducible water saturationand equilibrium between formation brine, the reservoir crude oil, andthe cation exchange sites, such that rock core sample includes aplurality of indigenous exchangeable cations adsorbed onto the cationexchange sites, a plurality of cation exchange sites occupied by a crudeoil, and one or more fluids occupying pore spaces in the rock coresample; subjecting the rock core sample to a plurality of corefloodingsteps, the plurality of coreflooding step displacing the plurality ofindigenous exchangeable cations, the crude oil, and the one or morefluids in at least two separate coreflooding steps to render the rockcore sample clean of the indigenous cations; determining an amount ofindigenous exchangeable cations adsorbed onto the cation exchange sites;and determining at least one property of different cation exchange sitesin the rock core sample based on the amount of indigenous exchangeablecations and the total amount of exchangeable cations.

In another aspect, embodiments disclosed herein relate to a method fordetermining an amount of different cation exchange sites occupied bycrude oil in a rock core sample, at a non-preserved state of the rockcore sample that includes providing a rock core sample in anon-preserved state; displacing all native components out of the porespace of the rock core sample by alternately injecting a first organicsolvent and a second organic solvent, wherein the second organic solventis the last injected; displacing the second organic solvent with aformation brine to adsorb a plurality of exchangeable cations onto thedifferent cation exchange sites of the rock core sample; displacing anexcess of cations from the formation brine present in a plurality ofinterstitial pore spaces of the rock core sample by using a thirdorganic solvent; displacing the plurality of exchangeable cationsadsorbed onto the different cation exchange sites of the rock coresample with a first injection fluid until completion of extraction;displacing the first injection fluid with the formation brine such thatthe cations present in the formation brine adsorb onto the cationexchange sites; injecting a reservoir crude oil into the rock coresample until reaching irreducible water saturation and equilibriumbetween formation brine, the reservoir crude oil, and the cationexchange sites, such that rock core sample includes a plurality ofindigenous exchangeable cations adsorbed onto the cation exchange sites,a plurality of cation exchange sites occupied by a crude oil, and one ormore fluids occupying pore spaces in the rock core sample; displacingthe reservoir crude oil in the rock core sample with formation brineuntil oil ceases production; displacing an excess of cations present ina plurality of interstitial pore spaces of the rock core sample by usinga fourth organic solvent; displacing the plurality of indigenous cationsadsorbed onto the cation exchange sites of the rock core sample with asecond injection fluid until completion of extraction; calculating anamount of indigenous exchangeable cations adsorbed onto the cationexchange sites and a total amount of the exchangeable cations adsorbedonto the cation exchange sites; and calculating the amount of thedifferent cation exchange sites occupied by crude oil based on theamount of indigenous exchangeable cations adsorbed onto the cationexchange sites and the total amount of the exchangeable cations adsorbedonto the cation exchange sites.

In yet another aspect, embodiments disclosed herein relate to a methodfor determining a wettability of different cation exchange sites of arock sample, at a non-preserved state of the rock core sample thatincludes providing a rock core sample in a non-preserved state;displacing all native components out of the pore space of the rock coresample by alternately injecting a first organic solvent and a secondorganic solvent, wherein the second organic solvent is the lastinjected; displacing the second organic solvent with a formation brineto adsorb a plurality of exchangeable cations onto the different cationexchange sites of the rock core sample; displacing an excess of cationsfrom the formation brine present in a plurality of interstitial porespaces of the rock core sample by using a third organic solvent;displacing the plurality of exchangeable cations adsorbed onto thedifferent cation exchange sites of the rock core sample with a firstinjection fluid until completion of extraction; displacing the firstinjection fluid with the formation brine such that the cations presentin the formation brine adsorb onto the cation exchange sites; injectinga reservoir crude oil into the rock core sample until reachingirreducible water saturation and equilibrium between formation brine,the reservoir crude oil, and the cation exchange sites, such that rockcore sample includes a plurality of indigenous exchangeable cationsadsorbed onto the cation exchange sites, a plurality of cation exchangesites occupied by a crude oil, and one or more fluids occupying porespaces in the rock core sample; displacing the reservoir crude oil inthe rock core sample with formation brine until oil ceases production;displacing an excess of cations present in a plurality of interstitialpore spaces of the rock core sample by using a fourth organic solvent;displacing the plurality of indigenous cations adsorbed onto the cationexchange sites of the rock core sample with a second injection fluiduntil completion of extraction; calculating an amount of indigenousexchangeable cations adsorbed onto the cation exchange sites and a totalamount of the exchangeable cations adsorbed onto the cation exchangesites; and calculating the wettability of the different cation exchangesites based on the amount of indigenous exchangeable cations adsorbedonto the cation exchange sites and the total amount of the exchangeablecations adsorbed onto the cation exchange sites.

Other aspects and advantages of the claimed subject matter will beapparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a flow chart according to one or more embodiments of thepresent disclosure.

FIGS. 2-9 show schematics of a rock core sample during sequentialcoreflooding operations in accordance with one or more embodiments ofthe present disclosure.

DETAILED DESCRIPTION

In one aspect, embodiments disclosed herein relate to methods of rocksample analysis to provide determinations concerning different cationexchange sites present in the rock core samples. Clay minerals in areservoir or rock sample have negatively charged sites (X⁻) on theirsurfaces which adsorb and hold cations (e.g., Ca²⁺, Mg²⁺, Na⁺, and K⁺)by electrostatic force. In particular, the present methods are directedto methodologies that allow for determinations concerning thewettability of different cation exchange sites in a rock core sampleand/or different cation exchange site occupied by crude oil, when therock is in a non-preserved state (i.e. not in the original reservoircondition).

Conventional methods of rock core analysis do not provide fordistinctions based on different cation exchange sites, i.e.,differentiating between Ca²⁺, Mg²⁺, Na⁺, and K⁺, for example. Moreover,conventionally, such testing should occur on a rock in preserved states.However, in accordance with embodiments of the present disclosure, arock core sample in a non-preserved state may be subjected to a seriesof coreflood steps to provide such differentiation and in particular thewettability of the different sites and which of the different sites areoccupied by crude oil. This may advantageously allow for enhanced oilrecovery operations to be designed based on such different cationexchange sites and the properties thereof to result in greater efficacyin EOR operations. In particular, such determinations may be made byconsidering the indigenous exchangeable cations of Na⁺, K⁺, Ca²⁺ andMg²⁺ adsorbed onto cation exchange sites ([NaX]_(e), [KX]_(e),[CaX₂]_(e) and [MgX₂]_(e)) and the total exchangeable cations of Na⁺,K⁺, Ca²⁺ and Mg²⁺ adsorbed onto the cation exchange sites, ([NaX]_(T),[KX]_(T), [CaX₂]_(T) and [MgX₂]_(T)). As used herein, the totalexchangeable cations adsorbed onto the cation exchange sites refers towhen all cation exchange sites are occupied by cations, whereas theindigenous exchangeable cations adsorbed onto the cation exchange sitesin the native state in the reservoir. For example, depending on thewettability of the rock surface and the cation exchange sites, inparticular, and whether the sites are oil-wet or water-wet, for example,some of the site may be occupied by crude oil, rather than cations. Thepresent methods may determine the wettability of each exchange siteand/or the amount of each site occupied by crude oil, for a rock samplethat is not in a preserved state. As used herein, when the rock is in apreserved state, it, and specifically the cation exchange sites, is inthe original reservoir condition, whereas a non-preserved state is notin the original reservoir condition.

As described herein, the present methodology uses coreflooding tosequentially displace native components out of the rock core sample andinject (and displace) replacement fluids therethrough during theanalysis. In particular, because the rock sample is not in a preservedstate, the present methods displace all native components fromtherefrom. Once the pore space of the rock core sample is entirelycleaned of all native components, the rock core sample may be filledwith formation brine having cations (of the indigenous type) in order toobtain data concerning the total exchangeable sites (which may be onlypartially occupied by indigenous cations in the reservoir). Then,reservoir crude oil may be injected into the rock sample until reachingirreducible water saturation and equilibrium to replicate the rocksample in a native state. Then, the present method may separatelydisplace excess components such as fluids (including excess cations)from the pore spaces, then indigenous cations from exchange sites (byreplacing the indigenous cations with replacement cations). Both theindigenous adsorbed cations and the “total” adsorbed cations may bequantified and compared in order to determine the wettability of eachexchange site and/or the amount of each site occupied by crude oil.

Such a coreflooding system may include a coreholder, a pumping system,an effluent collection system, a measurement system, as well astemperature and pressure control so that coreflooding experiments may beconducted at conditions mimicking reservoir conditions. Such systems arecommercially available. Coreflooding may be utilized on rock typeshaving a permeability of at least 0.1 millidarcy.

Referring now to FIG. 1, a flow chart according to one or moreembodiments is shown. As shown, stage 10 may include providing a rockcore sample in a non-preserved state. Stage 20 may include displacingall native components out of the rock core sample. Stage 30 may includesubjecting the rock core sample clean of native components to aplurality of coreflooding steps to determine a total amount ofexchangeable cations adsorbed onto the cation exchange sites when therock core sample is clean of native components. State 40 may includeinjecting formation brine and then a reservoir crude oil into the rockcore sample until reaching irreducible water saturation and equilibriumbetween formation brine, the reservoir crude oil, and the cationexchange sites, such that rock core sample includes a plurality ofindigenous exchangeable cations adsorbed onto the cation exchange sites,a plurality of cation exchange sites occupied by a crude oil, and one ormore fluids occupying pore spaces in the rock core sample. Stage 50 mayinclude subjecting the rock core sample to a plurality of corefloodingsteps, the plurality of coreflooding step displacing the plurality ofindigenous exchangeable cations, the crude oil, and the one or morefluids in at least two separate coreflooding steps to render the rockcore sample clean of the indigenous cations. Stage 60 may includedetermining an amount of indigenous exchangeable cations adsorbed ontothe cation exchange sites. Stage 70 may include determining at least oneproperty of different cation exchange sites in the rock core samplebased on the amount of indigenous exchangeable cations and the totalamount of exchangeable cations.

FIGS. 2-9 illustrate schematics of a rock core sample 80 duringprogressive stages of the present coreflooding operations. Initially,the rock core sample 80 in the non-preserved state (i.e., not atoriginal reservoir conditions) has a plurality of rock particles 85. Therock particles have exchange sites 90 present on the surface thereof.While there may be exchangeable cations 95 adsorbed to the exchangesites, because the rock core sample 80 is a non-preserved stated, theexchangeable cations 90 may not be used in determining the properties ofthe exchange sites. Thus, the rock core sample is coreflooded with analternating sequence of a plurality of organic solvents. Such organicsolvents may include at least one solvent that may be effective toremove any residual oil present in the rock core sample 80, includingoil adsorbed to the exchange sites 90 as well as residual oil present inthe pore spaces between rock particles. The effect of such corefloodingis shown in FIG. 2. Additionally, the organic solvents may also includeat least one solvent that is effective to remove water and salts fromthe pore space of the rock core sample 80. In one or more embodiments,one solvent may be toluene and the other may be methanol. It isenvisioned that the solvent miscible in water (e.g., methanol) may bethe last organic solvent injected into the rock core sample 80 (suchthat the water-miscible organic solvent can be completely displaced outof the rock core sample by formation brine as described in the followingparagraph). As shown in FIG. 2, the rock core sample 80, afteralternating injection of organic solvents, may have the exchangeablecations 95 adsorbed to the exchange sites 90, with the pore space beingoccupied entirely by the water-miscible organic solvent 145.

Following the alternating solvent injection, the effect of which isillustrated in FIG. 2, a formation brine may be coreflooded into therock core sample 80 to displace the water-miscible organic solvent 145from the rock sample core 80. As shown in FIG. 3, following suchdisplacement, formation brine 150 may be present in the pore spacesbetween rock particles 85. Formation brine 150 is injected in sufficientvolume for complete displacement of organic solvent (145 in FIG. 2).Cations in formation brine exchange with exchangeable cations 95 suchthat exchangeable cations 155 are adsorbed to all exchange sites 90present on the surface of rock particles 85. Because exchangeablecations 155 are adsorbed to all exchange sites 90, exchangeable cations155 are referred to herein as “total” exchangeable cations 155. Excesscations 160 in formation brine 150 are also present in the pore spacesbetween rock particles 85. In order to have complete displacement andequilibrium of the exchange sites 90, a large volume of formation brine150 may be used, for example, ranging from an estimated 50 to 80 porevolumes. For the purpose of estimating the volume of formation brine orother fluid that may be used for the coreflooding, the pore volume maybe estimated by measuring the length and diameter and assuming aporosity of 30% for the rock core sample.

In one or more embodiments, the pore volume of the rock core sample 80may be determined by NMR. Preferably, this determination may beperformed as the rock core sample 80 is in a state illustrated in FIG.3, as the rock core sample 80 contains a single fluid type therein,which may allow for fewer complexities in the NMR determination. Thepore volume may be used to quantify the amount of cations relative tothe pore volume of the rock core sample 80. However, a NMR analysisperformed at another time may account for the presence of more than onefluid, such as a brine and oil.

After equilibrating the exchange sites 90 with cations 155, the resultof which is shown in FIG. 3, the excess cations 160 may be removed fromthe rock core sample 80. As shown in FIG. 4, excess cations andformation brine (160 and 150, respectively, in FIG. 3) may be displacedfrom the pore spaces between rock particles 85 by coreflooding the rocksample 80 with an organic solvent, such as but not limited 95% ethanol,to displace the excess cations 160 (shown in FIG. 3) from the rock coresample 80. To complete the displacement of excess cations 160, a largevolume of organic solvent may be used, for example, ranging from 50 to80 pore volumes. The effect of such displacement is shown in theschematic illustrated in FIG. 4. As shown in FIG. 4, while the exchangesites 90 still have the “total” exchangeable cations 155 adsorbedthereto, the pore space between the rock particles 85 is now occupied byorganic solvent 165.

At this stage, the rock sample 80 may be coreflooded in order to removethe “total” exchangeable cations 155 from the sample 80 in order toquantify the total amount of cations adsorbed to exchange sites 90. Suchquantification may occur by displacement of the exchangeable cations 155(as well as organic solvent 165) from the rock sample with a secondinjection fluid 170, the effect of which is shown in FIG. 5. Injectionfluid 170 may include a replacement cation 175, such as NH₄ ⁺ adsorbedonto the exchange sites 90. Additionally, injection fluid 170 may alsoinclude excess replacement cations 180 that are not adsorbed onto theexchange sites 90, but which are present in the injection fluid 170. Toensure complete displacement of total exchangeable cations 155, theabout 50-80 pore volumes of injection fluid 170 may be injected intorock sample 80. In one or more embodiments, the injection fluid 170 maybe an ammonium acetate solution, having a concentration ranging from 0.5to 2.0 M and a pH ranging from 7 to 8.5. It is also envisioned thatother injection fluids such as hexaaminecobalt (III) chloride may beused.

From the extract collected from the coreflooding with the injectionfluid 170, the amount/concentration of the total exchangeable cations(those cations 155 that are adsorbed to all exchange sites 90, e.g.,Na⁺, K⁺, Ca²⁺ and Mg²⁺) in the injection fluid extract may be determinedby analytical methods, such as but not limited to ion chromatography(IC) specifically cation chromatography, atomic spectroscopic methodssuch as atomic absorption spectroscopy (AAS), inductively coupledplasma-mass spectrometry (ICP-MS), atomic emission spectrometry(ICP-AES), and optical emission spectrometry (ICP-OES), as well ascapillary electrophoresis (CE). In one or more embodiments, the totalamount of indigenous exchangeable cations may be considered as a moleequivalent per liter of pore volume and represented as [NaX]_(T),[KX]_(T), [CaX₂]_(T), and [MgX₂]_(T).

Having determined a total amount of exchangeable cations adsorbed ontoexchange sites, the rock core sample 80 may be coreflooded withformation brine to displace the second injection fluid 170, thereplacement cation 175, and the excess replacement cations 180 from therock sample core 80. As shown in FIG. 6, following such displacement,formation brine 150 may be present in the pore spaces between rockparticles 85. Formation brine 150 is injected in sufficient volume forcomplete displacement of the second injection fluid 170, the replacementcation 175, and the excess replacement cations 180 from the rock samplecore 80, such that exchangeable cations 155 are adsorbed to all exchangesites 90 present on the surface of rock particles 85 and excess cations160 in formation brine 150 are also present in the pore spaces betweenrock particles 85. In order to have complete displacement andequilibrium of the exchange sites 90, a large volume of formation brine150 may be used, for example, ranging from an estimated 50 to 80 porevolumes. Following the formation brine flooding, the rock core sample 80may be coreflooded with a reservoir crude oil until reaching irreduciblewater saturation and equilibrium between formation brine, crude oil, andcation exchange sites 90. In particular, a large volume of reservoircrude oil may be used, such as about 50-80 pore volumes. Reaching suchequilibrium, the rock core sample 80, while originally in anon-preserved state, has now been brought into an estimated native statebased on the injection of formation brine and reservoir crude oil untilreaching irreducible water saturation and equilibrium at the exchangesites 90.

After being brought to an estimated native state, the rock core sample80 may be coreflooded with formation brine to displace crude oil fromthe rock core sample. Formation brine may be injected until oil ceasesproduction from the rock core sample. Referring to FIG. 7, FIG. 7 showsa schematic of a rock core sample 80 following the coreflooding withformation brine to displace crude oil. As shown in FIG. 7, rockparticles 85 have exchange sites 90 present on the surface thereof. Theexchange sites 90 are shown to have some cations 100 and some oil 105adsorbed thereto. The cations 100 adsorbed onto the exchange sites 90are referred to as the indigenous exchangeable cations. Otherwise,following the coreflooding with a formation brine 110, the pore spacesbetween the rock particles 85 are occupied by formation brine 110,including an excess of cations 115 (not adsorbed to exchange sites 90)therein. It is also envisioned that some quantity of residual oil 120may also be present in the pore spaces between rock particles 85.

Following the displacement illustrated in FIG. 7, the rock core sample80 may be coreflooded with an organic solvent, such as but not limitedto 95% ethanol, to displace the excess cations 115 (shown in FIG. 7)from the rock core sample 80. To complete the displacement of excesscations 115, a large volume of organic solvent may be used, for example,ranging from an estimated 50 to 80 pore volumes. The effect of suchdisplacement is shown in the schematic illustrated in FIG. 8. As shownin FIG. 8, while the exchange sites 90 still have the cations 100 andoil 105 adsorbed thereto, the pore space between the rock particles 85is now occupied by organic solvent 125.

Following the displacement of excess cations, the effect of which isillustrated in FIG. 8, the rock core sample 80 is conducted with aninjection fluid to displace the cations 100 (i.e., indigenousexchangeable cations) adsorbed on the exchange sites 90 out of the rocksample 80, the effect of which is illustrated in the schematic shown inFIG. 9. As shown in FIG. 9, following such displacement, in addition todisplacing cations (100 in FIG. 8), the organic solvent (125 in FIG. 8)is also displaced from the rock sample 80 such that the pore spacebetween the rock particles 85 is occupied by injection fluid 130 in FIG.9. Injection fluid 130 may include a replacement cation 135, such as NH₄⁺ adsorbed onto the exchange sites 90. Additionally, injection fluid 130may also include excess replacement cations 140 that are not adsorbedonto the exchange sites 90, but which are present in the injection fluid130. To ensure complete displacement of indigenous exchangeable cations100, about 50-80 pore volumes of injection fluid 130 may be injectedinto rock sample 80. In one or more embodiments, the injection fluid 130may be an ammonium acetate solution, having a concentration ranging from0.5 to 2.0M and a pH ranging from 7 to 8.5. It is also envisioned thatother injection fluids such as a hexaaminecobalt (III) chloride solutionmay be used.

From the extract collected from the coreflooding with the injectionfluid, the amount/concentration of the indigenous exchangeable cations(those cations 100 that were adsorbed to exchange sites 90, e.g., Na⁺,K⁺, Ca²⁺ and Mg²⁺ after the rock core sample 80 was brought to anestimated native state) in the injection fluid extract may be determinedby analytical methods, such as but not limited to ion chromatography(IC) specifically cation chromatography, atomic spectroscopic methodssuch as atomic absorption spectroscopy (AAS), inductively coupledplasma-mass spectrometry (ICP-MS), atomic emission spectrometry(ICP-AES), and optical emission spectrometry (ICP-OES), as well ascapillary electrophoresis (CE). In one or more embodiments, the amountof indigenous exchangeable cations may be considered as a moleequivalent per liter of pore volume and represented as [NaX]_(e),[KX]_(e), [CaX₂]_(e), and [MgX₂]_(e).

Depending on whether the wettability of each exchange site and/or theamount of each site occupied by crude oil is to be determined, a seriesof calculations may be performed using [NaX]_(e), [KX]_(e), [CaX₂]_(e),and [MgX₂]_(e) and [NaX]_(T), [KX]_(T), [CaX₂]_(T), and [MgX₂]_(T).

In one or more embodiments, the wettability of Na⁺, K⁺, Ca²⁺, and Mg²⁺exchange sites may be determined. The wettability of each of Na⁺, K⁺,Ca²⁺, and Mg²⁺ exchange sites may be represented by W_(NaX), W_(KX),W_(CaX2), and W_(MgX2) and the following equations (1)-(4):

$\begin{matrix}{W_{NaX} = \frac{\left\lbrack {NaX} \right\rbrack_{T} - \left\lbrack {NaX} \right\rbrack_{e}}{\left\lbrack {NaX} \right\rbrack_{T}}} & (1) \\{W_{KX} = \frac{\left\lbrack {KX} \right\rbrack_{T} - \left\lbrack {KX} \right\rbrack_{e}}{\left\lbrack {KX} \right\rbrack_{T}}} & (2) \\{W_{CaX_{2}} = \frac{\left\lbrack {CaX_{2}} \right\rbrack_{T} - \left\lbrack {CaX_{2}} \right\rbrack_{e}}{\left\lbrack {CaX_{2}} \right\rbrack_{T}}} & (3) \\{W_{MgX_{2}} = \frac{\left\lbrack {MgX_{2}} \right\rbrack_{T} - \left\lbrack {MgX_{2}} \right\rbrack_{e}}{\left\lbrack {MgX_{2}} \right\rbrack_{T}}} & (4)\end{matrix}$

where a value of W=1 means the exchange site is completely oil-wet, anda value of W=0 means the exchange site is completely water-wet. Further,as is apparent, the wettability is calculated for each differentexchange site present in the rock core sample.

In one or more embodiments, which of Na⁺, K⁺, Ca²⁺, and Mg²⁺ exchangesites are occupied by crude oil may be determined. The amount (in moleequivalent per liter of pore volume) of the Na⁺, K⁺, Ca²⁺, and Mg²⁺exchange sites that are occupied by crude oil may be represented by[NaX]_(O), [KX]_(O), [CaX₂]_(O), and [MgX₂]_(O) and the followingequations (5)-(8):

[NaX]_(O)═[NaX]_(T)−[NaX]_(e)  (5)

[KX]_(O)═[KX]T−[KX]_(e)  (6)

[CaX₂]_(O)═[CaX₂]_(T)−[CaX₂]_(e),  (7)

[MgX₂]_(O)═[MgX₂]_(T)−[MgX₂]_(e),  (8)

Advantageously, the methods of the present application may provide fordeterminations concerning cation exchange sites in a rock sample,specifically, wettability and/or which are occupied by crude oil, in amanner that differentiates between different cation exchange sites, suchas Na⁺, K⁺, Ca²⁺, and Mg²⁺. Moreover, such properties may be determinedeven for a rock core sample that that has not been preserved inreservoir conditions. Using such determinations, an enhanced oilrecovery operation may be better designed, for example, in terms of thecompositional components included in an EOR injection fluid, whether inwater flooding or chemical flooding such as surfactant flooding, polymerflooding, alkaline/surfactant/polymer flooding, or reservoir preflushesfor the chemical flooding processes or the like.

Although only a few example embodiments have been described in detailabove, those skilled in the art will readily appreciate that manymodifications are possible in the example embodiments without materiallydeparting from this invention. Accordingly, all such modifications areintended to be included within the scope of this disclosure as definedin the following claims. In the claims, means-plus-function clauses areintended to cover the structures described herein as performing therecited function and not only structural equivalents, but alsoequivalent structures. Thus, although a nail and a screw may not bestructural equivalents in that a nail employs a cylindrical surface tosecure wooden parts together, whereas a screw employs a helical surface,in the environment of fastening wooden parts, a nail and a screw may beequivalent structures. It is the express intention of the applicant notto invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of theclaims herein, except for those in which the claim expressly uses thewords ‘means for’ together with an associated function.

What is claimed:
 1. A method for determining properties of differentcation exchange sites in a rock core sample, at a non-preserved state ofthe rock core sample, the method comprising: providing a rock coresample in a non-preserved state; displacing all native components out ofthe rock core sample; subjecting the rock core sample clean of nativecomponents to a plurality of coreflooding steps to determine a totalamount of exchangeable cations adsorbed onto the cation exchange siteswhen the rock core sample is clean of native components; injectingformation brine and then a reservoir crude oil into the rock core sampleuntil reaching irreducible water saturation and equilibrium betweenformation brine, the reservoir crude oil, and the cation exchange sites,such that rock core sample includes a plurality of indigenousexchangeable cations adsorbed onto the cation exchange sites, aplurality of cation exchange sites occupied by a crude oil, and one ormore fluids occupying pore spaces in the rock core sample; subjectingthe rock core sample to a plurality of coreflooding steps, the pluralityof coreflooding step displacing the plurality of indigenous exchangeablecations, the crude oil, and the one or more fluids in at least twoseparate coreflooding steps to render the rock core sample clean of theindigenous cations; determining an amount of indigenous exchangeablecations adsorbed onto the cation exchange sites; and determining atleast one property of different cation exchange sites in the rock coresample based on the amount of indigenous exchangeable cations and thetotal amount of exchangeable cations.
 2. The method of claim 1, whereinthe subjecting the rock core sample clean of native components to aplurality of coreflooding steps comprises: alternately injecting a firstorganic solvent and a second organic solvent, wherein the second organicsolvent is the last injected to render the pore space of the rock coresample clean of native components.
 3. The method of claim 1, wherein thesubjecting the rock core sample clean of native components to aplurality of coreflooding steps: coreflooding the rock sample clean ofnative components with the formation brine such that the cations presentin the formation brine adsorb onto the cation exchange sites and anexcess of cations are present in the plurality of interstitial porespaces of the rock core sample clean of native components; displacingthe excess of cations present in a plurality of interstitial pore spacesof the rock core sample by using a third organic solvent; and displacingthe cations adsorbed onto the cation exchange sites of the rock coresample with a first injection fluid until completion of extraction. 4.The method of claim 1, wherein the subjecting the rock core sample to aplurality of coreflooding steps comprises: displacing the firstinjection fluid with the formation brine such that the cations presentin the formation brine adsorb onto the cation exchange sites; injectinga reservoir crude oil into the rock core sample until reachingirreducible water saturation and equilibrium between formation brine,the reservoir crude oil, and the cation exchange sites, such that rockcore sample includes a plurality of indigenous exchangeable cationsadsorbed onto the cation exchange sites, a plurality of cation exchangesites occupied by a crude oil, and one or more fluids occupying porespaces in the rock core sample; displacing the crude oil in the rockcore sample with a formation brine until oil ceases production;displacing an excess of cations present in a plurality of interstitialpore spaces of the rock core sample by using a fourth organic solvent;and displacing the plurality of indigenous exchangeable cations from thecation exchange sites of the rock core sample with a second injectionfluid until completion of extraction.
 5. The method of claim 3, whereinthe total amount of exchangeable cations is quantified from an extractof the first injection fluid upon completion of extraction by ananalytical method.
 6. The method of claim 4, wherein the amount ofindigenous exchangeable cations is quantified from an extract of thesecond injection fluid upon completion of extraction by an analyticalmethod.
 7. The method of claim 1, further comprising: determining a porevolume of the rock core sample.
 8. The method of claim 3, wherein thefirst injection fluid is an ammonium acetate solution.
 9. The method ofclaim 4, wherein the second injection fluid is an ammonium acetatesolution.
 10. The method of claim 2, wherein the first organic solventis toluene and the second organic solvent is methanol.
 11. The method ofclaim 3, wherein the third organic solvent is ethanol.
 12. The method ofclaim 4, wherein the fourth organic solvent is ethanol.
 13. A method fordetermining an amount of different cation exchange sites occupied bycrude oil in a rock core sample, at a non-preserved state of the rockcore sample, the method comprising: providing a rock core sample in anon-preserved state; displacing all native components out of the porespace of the rock core sample by alternately injecting a first organicsolvent and a second organic solvent, wherein the second organic solventis the last injected; displacing the second organic solvent with aformation brine to adsorb a plurality of exchangeable cations onto thedifferent cation exchange sites of the rock core sample; displacing anexcess of cations from the formation brine present in a plurality ofinterstitial pore spaces of the rock core sample by using a thirdorganic solvent; displacing the plurality of exchangeable cationsadsorbed onto the different cation exchange sites of the rock coresample with a first injection fluid until completion of extraction;displacing the first injection fluid with the formation brine such thatthe cations present in the formation brine adsorb onto the cationexchange sites; injecting a reservoir crude oil into the rock coresample until reaching irreducible water saturation and equilibriumbetween formation brine, the reservoir crude oil, and the cationexchange sites, such that rock core sample includes a plurality ofindigenous exchangeable cations adsorbed onto the cation exchange sites,a plurality of cation exchange sites occupied by a crude oil, and one ormore fluids occupying pore spaces in the rock core sample; displacingthe reservoir crude oil in the rock core sample with formation brineuntil oil ceases production; displacing an excess of cations present ina plurality of interstitial pore spaces of the rock core sample by usinga fourth organic solvent; displacing the plurality of indigenous cationsadsorbed onto the cation exchange sites of the rock core sample with asecond injection fluid until completion of extraction; calculating anamount of indigenous exchangeable cations adsorbed onto the cationexchange sites and a total amount of the exchangeable cations adsorbedonto the cation exchange sites; and calculating the amount of thedifferent cation exchange sites occupied by crude oil based on theamount of indigenous exchangeable cations adsorbed onto the cationexchange sites and the total amount of the exchangeable cations adsorbedonto the cation exchange sites.
 14. The method of claim 13, wherein theamount of indigenous exchangeable cations and the total amount ofexchangeable cations are quantified from extracts of the first injectionfluid and second injection fluid upon completion of extraction byanalytical methods.
 15. The method of claim 13, further comprising:determining a pore volume of the rock core sample.
 16. The method ofclaim 13, wherein the calculating the amount of different cationexchange sites occupied by crude oil uses equations (5)-(8):[NaX]_(O)═[NaX]_(T)−[NaX]_(e)  (5)[KX]_(O)═[KX]_(T)−[KX]_(e)  (6)[CaX₂]_(O)═[CaX₂]_(T)−[CaX₂]_(e),  (7)[MgX₂]_(O)═[MgX₂]T−[MgX₂]_(e),  (8) wherein [NaX]_(O), [KX]_(O),[CaX₂]_(O), and [MgX₂]_(O) represent Na⁺, K⁺, Ca²⁺, and Mg²⁺ exchangesites that are occupied by crude oil; [NaX]_(T), [KX]_(T), [CaX₂]_(T),and [MgX₂]_(T) represent the total amount of exchangeable cations ofNa⁺, K⁺, Ca²⁺, and Mg²⁺ adsorbed onto cation exchange sites, and[NaX]_(e), [KX]_(e), [CaX₂]_(e), and [MgX₂]_(e) represent the amount ofindigenous cations of Na⁺, K⁺, Ca²⁺, and Mg²⁺ adsorbed onto cationexchange sites.
 17. A method for determining a wettability of differentcation exchange sites of a rock sample, at a non-preserved state of therock core sample, the method comprising: providing a rock core sample ina non-preserved state; displacing all native components out of the porespace of the rock core sample by alternately injecting a first organicsolvent and a second organic solvent, wherein the second organic solventis the last injected; displacing the second organic solvent with aformation brine to adsorb a plurality of exchangeable cations onto thedifferent cation exchange sites of the rock core sample; displacing anexcess of cations from the formation brine present in a plurality ofinterstitial pore spaces of the rock core sample by using a thirdorganic solvent; displacing the plurality of exchangeable cationsadsorbed onto the different cation exchange sites of the rock coresample with a first injection fluid until completion of extraction;displacing the first injection fluid with the formation brine such thatthe cations present in the formation brine adsorb onto the cationexchange sites; injecting a reservoir crude oil into the rock coresample until reaching irreducible water saturation and equilibriumbetween formation brine, the reservoir crude oil, and the cationexchange sites, such that rock core sample includes a plurality ofindigenous exchangeable cations adsorbed onto the cation exchange sites,a plurality of cation exchange sites occupied by a crude oil, and one ormore fluids occupying pore spaces in the rock core sample; displacingthe reservoir crude oil in the rock core sample with formation brineuntil oil ceases production; displacing an excess of cations present ina plurality of interstitial pore spaces of the rock core sample by usinga fourth organic solvent; displacing the plurality of indigenous cationsadsorbed onto the cation exchange sites of the rock core sample with asecond injection fluid until completion of extraction; calculating anamount of indigenous exchangeable cations adsorbed onto the cationexchange sites and a total amount of the exchangeable cations adsorbedonto the cation exchange sites; and calculating the wettability of thedifferent cation exchange sites based on the amount of indigenousexchangeable cations adsorbed onto the cation exchange sites and thetotal amount of the exchangeable cations adsorbed onto the cationexchange sites.
 18. The method of claim 17, wherein the amount ofindigenous exchangeable cations and the total amount of exchangeablecations are quantified from extracts of the first injection fluid andsecond injection fluid upon completion of extraction by analyticalmethods.
 19. The method of claim 17, further comprising: determining apore volume of the rock core sample.
 20. The method of claim 17, whereinthe calculating the wettability of different cation exchange sites usesequations (1)-(4): $\begin{matrix}{W_{NaX} = \frac{\left\lbrack {NaX} \right\rbrack_{T} - \left\lbrack {NaX} \right\rbrack_{e}}{\left\lbrack {NaX} \right\rbrack_{T}}} & (1) \\{W_{KX} = \frac{\left\lbrack {KX} \right\rbrack_{T} - \left\lbrack {KX} \right\rbrack_{e}}{\left\lbrack {KX} \right\rbrack_{T}}} & (2) \\{W_{CaX_{2}} = \frac{\left\lbrack {CaX_{2}} \right\rbrack_{T} - \left\lbrack {CaX_{2}} \right\rbrack_{e}}{\left\lbrack {CaX_{2}} \right\rbrack_{T}}} & (3) \\{W_{MgX_{2}} = \frac{\left\lbrack {MgX_{2}} \right\rbrack_{T} - \left\lbrack {MgX_{2}} \right\rbrack_{e}}{\left\lbrack {MgX_{2}} \right\rbrack_{T}}} & (4)\end{matrix}$ wherein W_(NaX), W_(KX), W_(CaX2), and W_(MgX2) representwettability of Na⁺, K⁺, Ca²⁺, and Mg²⁺ exchange sites; [NaX]_(T),[KX]_(T), [CaX₂]_(T), and [MgX₂]_(T) represent the total amount ofexchangeable cations of Na⁺, K⁺, Ca²⁺, and Mg²⁺ adsorbed onto cationexchange sites, and [NaX]_(e), [KX]_(e), [CaX₂]_(e), and [MgX₂]_(e)represent the amount of indigenous cations of Na⁺, K⁺, Ca²⁺, and Mg²⁺adsorbed onto cation exchange sites.